Bituminous sands, commonly referred to as oil sands or tar sands, are a mixture of sand or clay, water, and bitumen. While tar sand deposits can be found in a number of different places in the world, the largest tar sand deposits are found in Canada. Most of the Canadian tar sands are located in three major deposits in northern Alberta. Some estimate the Alberta tar sands deposits to contain at least 85% of the world's total reserves of natural bitumen that are concentrated enough to be economically recoverable for conversion to oil at current prices.
Bitumen in its raw state is a heavy viscous crude oil which contains a high amount of sulfur. Because of this high viscosity, bitumen will not flow at reservoir conditions. The two most common bitumen production techniques currently employed are surface mining and in situ thermal recovery.
The largest bitumen deposit in Canada, containing about 80% of Canada's bitumen supply, and the only one suitable for surface mining is the Athabasca Oil Sands along the Athabasca River in Alberta. A smaller deposit is found in the Cold Lake region in Alberta, and is notable for having oil that is fluid enough to be extracted by conventional methods in some places. These Alberta areas are also suitable for bitumen production using known in-situ thermal methods such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD). These in situ operations involve drilling wells and injecting steam to heat the bitumen allowing it to flow and to be produced from a well.
The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s and is presently being used in several locations in Alberta. CSS, also known as “huff-and-puff” or steam stimulation involves alternately injecting, soaking and producing in a single well. This technique is popular in fields where oil mobility is too low to begin steam flooding immediately. In conventional CSS, steam is first injected into a well at a temperature of 300 to 340 degrees Celsius and at a pressure up to 2000 psi for a period of weeks to months to heat the bitumen (“injection” or the “huff”). The well is then allowed to sit for days to weeks to allow heat to soak into the formation (“soak”). Then, hot water and bitumen are pumped out of the well for a period of weeks or months (“production” or the “puff”). Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes uneconomic relative to the money made from producing oil.
SAGD was developed in the 1980s by an Alberta government research center and is now widely used in a number of new in situ projects. In conventional SAGD, a pair of horizontal wells are drilled in the tar sands, with one about 5 meters above the other. Initially, the area around and between the upper well (“injector well”) and the lower well (“producer well”) is warmed up by circulating steam through both wells; during this initial warming up, oil is not produced in commercially significant quantities. Following this, in each well pair, pressurized steam is injected into the injector well, and the heat from the steam melts the bitumen within the heated area or “steam chamber” formed by the steam. The bitumen then flows via gravity into the producer well, where it is pumped to the surface. Each well pair can produce up to 1000 to 1500 barrels per day and are typically spaced 100 to 200 m apart.
SAGD offers several significant advantages over CSS. CSS will typically recover 25-30% of the original bitumen in place over the life of the process, and requires steam to be provided at a higher pressure than SAGD. In contrast, SAGD can recover 60 to 70% of the bitumen in a more efficient manner: for CSS, the steam-oil-ratio (“SOR”) which measures the volume of steam required to extract the bitumen is between 3.0 and 6.0 for CSS and only 2.0 to 3.0 for SAGD. Therefore, significantly less energy, typically in the form of natural gas, is required to generate the steam necessary for the SAGD process.
While SAGD represents a technological advance in certain aspects of recovering oil from tar sands, it is not without its disadvantages. Because this technique relies on gravity for drainage, the process works best in relatively thick and homogeneous clean oil sand reservoirs. CSS in comparison, has been successfully employed in more diverse environments, and is more tolerant than SAGD to variations in reservoir quality.
Another variation of SAGD is known as “Fast-SAGD” has been disclosed, for example, by Polikar et al in H. Shin and M. Polikar, “Review of Reservoir Parameters to Optimize SAGD and Fast-SAGD Operating Conditions”, JCPT Vol. 46, No. 1, January 2007, in U.S. Pat. No. 6,257,334, and by Polikar, M. Cyr, T. J. and Coates, R. M., in “Fast-SAGD: Half the Wells and 30% Less Steam”, Paper No. SPE 65509/PS2000-148, Proc. 4th International Conference on Horizontal Well Technology, Calgary, Alberta (Nov. 6-8, 2000). In Fast-SAGD as disclosed by these publications, an extra single horizontal well is placed between two SAGD well pairs. While the SAGD process is implemented at the SAGD well pairs, steam is injected at higher pressures into the single horizontal well in a cyclic mode in order to help propagate the steam chambers laterally along with the SAGD operation. After several steam cycles at the single well, the single well and SAGD wells are in thermal communication. Then, the single well is converted to production for the remainder of its well life. Meanwhile, steam injection continues into each SAGD injector well to maintain and expand the existing steam chamber, resulting in additional production compared to a convention SAGD operation.
As of the present writing, the proposed Fast-SAGD process has only been simulated and not field tested. The known simulations have only been conducted in idealized reservoirs with uniform properties. Further, the simulations have only been conducted using a two-dimensional vertical cross-section of a reservoir. As a result, the simulations have not taken into consideration the effects of variations in reservoir properties in the cross-section dimensions as well as in the direction of the horizontal wells. It is expected that Fast-SAGD will be problematic in real reservoirs with areal and vertical permeability variations. In nature, every oil sand accumulation will have a certain variation in permeability areally as well as vertically. The CSS wells in the Fast SAGD process operate at pressures that are significantly higher than the SAGD well pairs. The large pressure difference between the CSS and the SAGD wells eventually creates a short circuit between the two wells at which point the process has to be converted to conventional SAGD operation thereby reducing significantly the advantage that would be provided by the CSS well. FIG. 1 (Prior Art) shows a 3-dimensional simulation of a Fast-SAGD operation in the Clearwater Formation in the Cold Lake area of Alberta; data from the Cold Lake area representing actual reservoir permeability variations were used in this simulation. In this simulation, a short circuit has occurred between two adjacent wells on the left. That is, there is steam breakthrough from a CSS well on the left boundary of the model to an adjacent SAGD well. As there is a pressure differential between the CSS well and the SAGD wells, all of the steam will flow through the breakthrough instead of contributing to continued expansion of the steam chamber. Therefore, the process is converted to a SAGD operation at this point. It is further noted that the additional heated area provided by the CSS wells are far smaller than that would be expected as prescribed in the literature. The process performs better than a pure SAGD operation would due to an additional producer between the SAGD well pairs, but the expected performance is not reached. It is quite likely that the additional cost of CSS wells will not be worth while in this case. Consequently, the Fast SAGD process may have little practical application in real world applications.
With current in situ technologies, the tar sands in Alberta place Canada on par with Saudi Arabia in volume of recoverable oil reserves. Canada is already the largest supplier of crude oil and refined products to the U.S., with over a million barrels per day coming from tar sands. With the recent dramatic increases in oil prices and political volatility in the Middle East, there is strong motivation to develop even more efficient and effective technologies to recover oil from tar sands.